Petrophysical Training

Petrophysical Consulting

OIL, GAS, and ROCKS -- FOR BEGINNERS
This page is intended for people who have little experience in the
oil and gas industry who may be looking at a career path or a
university specialty that could lead to an interesting and rewarding
life. Most of the material here is covered in other Chapters of this
website but a few of the basic concepts have been gathered
here to give an overview of the subject of petrophysics.

All of my 50+ year career has been involved with the science of
Petrophysics, literally the physics of rocks, in some way or
another. Petrophysics is a branch of Geoscience and intimately
linked to geology, geophysics, and petroleum / mining
engineering. There is no degree granted in pure petrophysics, so
people in this field are often graduates of a closely related
specialty and are self-taught from there.

Petrophysics is mainly used in petroleum exploitation, but also
in defining mining and ground water resources.

To understand petrophysics, you need to understand rocks and the
fluids they contain, how the earth's surface and subsurface
change shape, and how pressure, temperature, and chemical
reactions change rocks and fluids over eons of time. That's a
tall order.

Rocks
are formed in several ways, but usually end up as moderately flat
layers, at least initially (mountain building comes later). As
successive layers are laid on top of each other, the Earth
builds a sequence of rocks with varying physical properties.
Some layers will have open spaces, called pores or porosity,
that contain fluids (water, oil, or gas). A rock on Earth with
porosity cannot be "empty" -- they must contain something, even
if it is only air.

Microphotograph of a rock -- dark blue colour is the porosity
where
oil, gas, and water can be held inside the rock

Think of a porous rock as similar to a
huge sponge full of holes that can soak up fluids. Although we
often talk about "oil pools", these are not tanks of oil
underground -- they are porous rocks. The porosity, or quantity
of open space relative to the total rock volume, can range from
near zero to as much as 40%. Obviously, higher values of this
physical property of a rock are good news.

Some
rocks have very little porosity and do not hold much in the way
of fluids. These are often called "tight" rocks. Both tight and
porous rocks can contain animal and plant residue that are
ultimately transformed into hydrocarbons such as coal, oil, or
natural gas that we can extract and use to power vehicles and
heat our homes. As the plant and animal residues mature into oil
or gas, they may migrate through porosity or natural fractures
in the rock until trapped by a non-porous rock structure.
Sometimes a rock only sources itself or an adjacent porous rock,
so little migration occurs.

An anticline, the simplest form of petroleum trap

Rocks that are capable of holding hydrocarbons in economic
quantities are called reservoir rocks. Rocks in which the plant
and animal residue has not been fully converted to useful
hydrocarbons are called source rocks. Some rocks are both source
and reservoir: others are barren of hydrocarbons, and some
others may act as the trapping mechanism that keeps hydrocarbons
from migrating to the surface and escaping.

A trap is what keeps oil and gas in the rocks until we drill
wells to extract the hydrocarbons. Coal, being a solid, doesn't
need a trap to be kept in place.

Reservoirs
that contain oil or gas also contain water. The quantity of
water relative to the porosity is called the water saturation.
In the illustrations, the brown colour is solid rock grains and
the space around the grains is the porosity. The black colour is
the hydrocarbon and the white is the water, which forms a thin
film coating the surfaces of each rock grain. This is a
water-wet reservoir (left). In an oil-wet reservoir, the black
and white colours are reversed (right).

Finding and evaluating the economics of such reservoirs is the
job of teams of geoscientists and engineers in petroleum and
mining companies. A petrophysicist, or someone playing this
role, will be part of that team.

Once a useful accumulation has been found, drilling, completion,
and production engineers take over to put wells on stream. Oil
production may initially flow to surface due to the pressure in
the reservoir. Some oil pools do not have enough pressure to do
this and need to be pumped. Depending on the reservoir drive
mechanism, some wells that start flowing will later need to be
pumped. Water may be produced with the oil. It is separated and
disposed of by re-injection into a nearby unproductive reservoir
layer. You can't just dump the water in the nearest swamp.

Aquifer Drive -- Before ... and After some production
Gas Cap Drive
Gas Expansion Drive

An aquifer drive mechanism usually maintains the reservoir
pressure for some time but may drop off gradually. Recovery factors vary from 30 to 80% of the oil in place. The oil water
contact rises as production depletes the oil. A gas cap drive
pushes oil out as the gas expands. Recovery factor is similar to
aquifer drive. There may or may not be some aquifer support.
the gas oil contact drops as the oil is depleted. Gas expansion
reservoirs do not have aquifer or gas cap support. Gas dissolved
in the oil expels oil into the well bore because the pressure at
the well bore is below the reservoir pressure. Recovery factor is
awful - usually less than 10%, but this can be improved to maybe
20% by injecting water nearby to increase or maintain the
reservoir pressure. Water floods, carbon dioxide injection, and
re-injection of produced gas or water can be used in nearly any
reservoir to improve recovery efficiency.

Gas wells do not need pumps, but if they also produce water, a
special process called artificial lift is used to get the water
out. That water is also disposed of legally.

The
economics of a reservoir varies with improving technology.
Bypassed reservoirs, discovered and ignored years ago, are now
economic due to technical improvements in drilling practices and
reservoir stimulation techniques. Horizontal wells and deep
water drilling are now common. The use of heat or steam to assist
production of heavy oil or bitumen, and multi-stage hydraulic fracturing to
stimulate production in tighter reservoirs are relatively new
techniques and relatively economic today. Obviously the specific
price of oil or gas after delivery to the customer plays an
important role in how much effort can be expended to recover oil
and gas from underground.

There is controversy, of course, about new technology. Just as
the Luddites resisted the weaving machines in the early 1800's,
modern Luddites insist that the old ways of oil and gas
extraction are best, while at the same time complaining loudly
about the price of gasoline at the pumps or the cost of
electricity for their air conditioners. You can't have low-cost
and low-tech at the same time.

Green
alternatives are 50 to 100 years away. Every green technology
needs oil to make the required plastics and fuel the
manufacturing and delivery
systems. The electricity grid is far too fragile to fuel
extensive use of electric vehicles anywhere, let alone everywhere. And where
would all that electricity come from (coal?). Clean coal is more
oxymoronic than military intelligence. So if you and the
other 7 Billion people on this planet want to live a comfortable
life, get used to oil and its risks. Staying in bed is risky too
-- more people die in bed than anywhere else.

For the record, I've been off the grid with wind or solar since 1984.
But I live in the middle of nowhere so the esthetics don't
bother the neighbours. What have
you done to green-up this world?

BASIC PETROPHYSICS"Last week, I couldn't spell Petrophysicist. Now I are one."
That describes me in 1962 as I moved from Montreal to Red Deer,
Alberta to run well logs for a company called Schlumberger. The
word petrophysics had been coined 20 years earlier by a
geologist named Gus Archie and it wasn't used much back in the
day. Lately it has attained a certain cachet, denoting a professional
level career path.

What is a "well log" you ask. It is a record of measurements of
physical properties of rocks taken in a well bore, usually
drilled for oil or gas, but possibly for ground water or
minerals. Think of a ship's log. The first record of such a log
dates back to 1846 when Lord Kelvin measured temperature
versus depth in water wells in England, from which he deduced
that the Earth was 7000 years old. The fact that he was wrong is
not important. Log analysis is an imperfect science.

Illustration of a wireline logging job: logging truck with
computer cabin, cable and winch (right), cable strung from
winch into drilling rig derrick and lowered into bore hole, with
logging tool at the end of the cable. Logs are recording while
pulling the tool up the hole. Logs can also be run with special
tools located at the bottom of the drilling string, or
conventional tools can be conveyed on coiled tubing or drill
pipe

The first logs for oil field investigation were run by the
Schlumberger brothers, Marcel and Conrad, in 1928 in
Pechebron, France. Soon, the service migrated to North and South
America, Russia, and other locations in Asia. At that time, the
only measurement that could be made was of the electrical
resistivity of the rocks. High resistivity meant porous rock
with oil or gas, or porous rock with fresh water, or tight rock
with very low porosity. Low resistivity meant porous rock with
salty water or shale. Take your pick. Local knowledge helped.

One virtue of the well log was that the top
and bottom of each rock layer could be defined quite accurately.
When the log and depths were compared to the rock sample chips
created by the drilling process, a reasonable geological
interpretation might be possible, but was far from infallible.

By 1932, the spontaneous potential (SP) measurement was added.
The analysis rules expanded: low SP meant shale, or tight rock,
or fresh water. High values meant salt water with or without
oil or gas in a porous rock. The resistivity could then be used
to decide on water versus hydrocarbons. Perfect. Except there
were lots of shades of grey and the SP was not always capable of
defining anything.

Logs from 1932 in Oil City-Titusville area, Pennsylvania, the
location of Edwin Drake's "First Oil Well" (in the USA - 6
other countries had oil wells predating this one). His well was only 69
feet deep, so it penetrated just to the top of these logs, which
found deeper and more prolific reservoirs.
Each pair of curves represents the measured data versus depth for
one well. The SP is the left hand curve of each pair; deflections to
the left (shaded) show porous rock. The resistivity is the curve on
the right of each pair. Deflections to the right (shaded) show high
resistivity, and when combined with a good SP deflection, indicate
oil zones. Some good quality rocks in this example do not have high
resistivity and are most likely water bearing.

The gamma ray log appeared in 1936. The rules
were easy: low value equaled porous reservoir or tight rocks.
High values were shale. It said nothing about fluid content.

By 1942, Gus Archie had defined a couple of quantitative methods
that turned analysis into a mathematical game, instead of just
some simple rules of thumb. His major work established a
relationship between resistivity, water saturation, and
porosity. If we knew porosity from rock samples measured in the
lab, and a few other parameters, we could calculate water
saturation from the resistivity log values. This was really new
news.

He even attempted to calculate porosity from the resistivity
log. This worked in high quality (high porosity) reservoirs but
had problems in low quality rocks or heavy oil.

Just after 1945, a method that investigated the response of
rocks to neutron bombardment became available. The neutron log
was the first porosity indicating well log. High values meant
low porosity or high porosity with gas. Low values meant high
porosity with oil or water, or shale. Add the gamma ray log, SP,
and resistivity and again the world was perfect, except for all
those shades of grey. Calibrating the response to porosity
depended on a lot of well bore environmental parameters (hole
size, mud weight, temperature) so it was not terribly accurate.

It wasn't until 1958 that the measurement of the velocity (or
travel time) of sound through rocks in a well bore was achieved.
It turned out that the travel time was a linear function of
porosity and a few other factors.

This is an example of a modern sonic log with gamma ray and
caliper curves (far left), shear and compressional sonic travel
time curves (middle) and sonic waveform image log (right).
Depths are shown in the narrow track next to the gamma ray
curve.

Shortly after 1960, another
porosity indicating log appeared that measured the apparent
density of the rocks. Porosity was a linear function of density
-- higher density meant lower porosity.

Both sonic travel time
and density as measured by these logs could be transformed into
moderately accurate porosity values, using the gamma ray to
discount shale, and the resistivity to distinguish between
salty water and oil. Fresh water was still a problem and gas
zones could only be located if a neutron log was also run.

This was the state of petrophysics when I entered the scene in
1962. The rules were obvious, the
math was easy. And running the logging tools into the well bore
meant lots of travel. I loved the job. There were no computers
on every desk, calculators were bigger and heavier than
typewriters, so the quantitative work was done with penciland
paper or sliderule. Anybody know what a sliderule is?

Later, with sidetracks into seismic data processing, reservoir
engineering, project management, and seismic data center
management, I finally noticed that petrophysics was the underlying
foundation of much of geology, geophysics, and reservoir
engineering.

That realization led me to my consulting and teaching career. I got to see a lot of
the world, wrote
a dozen or more
software packages, analyzed the log data from thousands of
wells, and saw even more of the world,

This may be the only editorial
cartoon ever published in a newspaper (Calgary Herald, circa
1974 - 75) concerning petrophysical analysis. That`s me peering down a borehole on Melville Island NWT,
estimating the gas reserves to be "four trillion cubic feet".
The final value was closer to 17 trillion. I was the log analyst
and logging supervisor on about 140 wells in the Canadian Arctic
across a 10 year period. We didn`t use our eyeballs to look into
the wellbores directly, of course; we used well logs and calcualtions based on those measurements to do what our eyes could not.

We now call the business "Integrated Petrophysics" because we
use much more than well log data to get our answers. Lab data from
core analysis, such as porosity, permeability and grain density,
are critical input parameters used to calibrate our work. More
exotic lab measurements have become more common as we move into
unconventional reservoir types like shale gas and tight oil
prospects.

TYPES and USES OF WELL
LOG and LABORATORY DATAThe table
below might not mean too much to someone who is not in the oil
and gas business, but it will give everyone an idea of the scope
of work, wealth of data types, and the multiplicity of uses that
petrophysical data can be applied to.